In recent years, industrial and utility concerns with deregulation and operational costs have strengthened demands for increased power plant efficiency. The Rankine cycle power plant, which typically utilizes water as the working fluid, has been the mainstay for the utility and industrial power industry for the last 150 years. In a Rankine cycle power plant, heat energy is converted into electrical energy by heating a working fluid flowing through tubular walls, commonly referred to as waterwalls, to form a vapor, e.g., turning water into steam. Typically, the vapor will be superheated to form a high pressure vapor, e.g., superheated steam. The high pressure vapor is used to power a turbine/generator to generate electricity.
Conventional Rankine cycle power generation systems can be of various types, including direct-fired, fluidized bed and waste-heat type systems. In direct fired and fluidized bed type systems, combustion process heat is generated by burning fuel to heat the combustion air which in turn heats the working fluid circulating through the systems waterwalls. In direct-fired Rankine cycle power generation systems the fuel, commonly pulverized-coal, gas or oil, is ignited in burners located in the waterwalls. In bubbling fluidized bed Rankine cycle power generation systems pulverized-coal is ignited in a bed located at the base of the boiler to generate combustion process heat. Waste-heat Rankine cycle power generation systems rely on heat generated in another process, e.g., incineration, for process heat to vaporize, and if desired superheat, the working fluid. Due to the metallurgical limitations, the highest temperature of the superheated steam does not normally exceed 1050.degree. F. (566.degree. C.). However, in some "aggressive" designs, this temperature can be as high as 1100.degree. F. (593.degree. C.).
Over the years, efficiency gains in Rankine cycle power systems have been achieved through technological improvements which have allowed working fluid temperatures and pressures to increase and exhaust gas temperatures and pressures to decrease. An important factor in the efficiency of the heat transfer is the average temperature of the working fluid during the transfer of heat from the heat source. If the temperature of the working fluid is significantly lower than the temperature of the available heat source the efficiency of the cycle will be significantly reduced. This effect, to some extent, explains the difficulty in achieving further gains in efficiency in conventional, Rankine cycle-based, power plants.
In view of the above, a departure from the Rankine cycle has recently been proposed. The proposed new cycle, commonly referred to as the Kalina cycle, attempts to exploit the additional degree of freedom available when using a binary fluid, more particularly an ammonia/water mixture, as the working fluid. The Kalina cycle is described in the paper entitled: "Kalina Cycle System Advancements for Direct Fired Power Generation", co-authored by Michael J. Davidson and Lawrence J. Peletz, Jr., and published by Combustion Engineering, Inc., of Windsor, Conn. Efficiency gains are obtained in the Kalina cycle plant by reducing the energy losses during the conversion of heat energy into electrical output.
A simplified conventional direct-fired Kalina cycle power generation system is illustrated in FIG. 1 of the drawings. Kalina cycle power plants are characterized by three basic system elements, the Distillation and Condensation Subsystem (DCSS) 100, the Vapor Subsystem (VSS) 110 which includes the boiler 142, superheater 144 and recuperative heat exchanger (RHE) 140, and the turbine/generator subsystem (TGSS) 130. The DCSS 100 and RHE 140 are sometimes jointly referred to as the Regenerative Subsystem (RSS) 150. The boiler 142 is formed of tubular walls 142a and the superheater 144 is formed of tubular walls and/or banks of fluid tubes 144a. A heat source 120 provides process heat 121. A portion 123 of the process heat 121 is used to vaporize the working fluid in the boiler 142. Another portion 122 of the process heat 121 is used to superheat the vaporized working fluid in the superheater 144.
During normal operation of the Kalina cycle power system of FIG. 1, the ammonia/water working fluid is fed to the boiler 142 from the RHE 140 by liquid stream FS 5 and from the DCSS 100 by liquid stream FS 7. The working fluid is vaporized, i.e., boiled, in the tubular walls 142a of the boiler 142. The FS rich working fluid stream 20 from the DCSS 100 is also vaporized in the heat exchanger(s) of the RHE 140.
In one implementation, the vaporized working fluid from the boiler 142 along with the vaporized working fluid FS 9 from the RHE 140, is further heated in the tubular walls/fluid tube bank 144a of the superheater 144. The superheated vapor from the superheater 144 is directed to and powers the TGSS 130 as FS vapor 40 so that electrical power 131 is generated to meet the load requirement. In an alternative implementation, the RHE 140 not only vaporizes but also superheats the rich stream FS 20. In such a case, the superheated vapor flow FS 9' from the RHE 140 is combined with the superheated vapor from the superheater 144 to form FS vapor flow 40 to the TGSS 130.
Expanded working fluid FS extraction 11 egresses from the TGSS 130, e.g., from a low pressure (LP) turbine (not shown) within the TGSS 130, and is directed to the DCSS 100. This expanded working fluid is, in part, condensed in the DCSS 100. Working fluid condensed in the DCSS 100, as described above, forms feed fluid FS 7 which is fed to the boiler 142. Another key feature of the DCSS 100 is the separation of the working fluid egressing from TGSS 130 into ammonia rich and ammonia lean streams for use by the VSS 110. In this regard, the DCSS 100 separates the expanded working fluid into an ammonia rich working fluid flow FS rich 20 and an ammonia lean working fluid flow FS lean 30. Waste heat 101 from the DCSS 100 is dumped to a heat sink, such as a river or pond.
The rich and lean flows FS 20, FS 30, respectively, are fed to the RHE 140. Another somewhat less expanded hot working fluid FS extraction 10 egresses from the TGSS 130, e.g., from a high pressure (HP) turbine (not shown) within the TGSS 130, and is directed to the RHE 140. Heat is transferred from the expanded working fluid FS extraction 10 and the working fluid FS lean stream 30 to the rich working fluid flow FS rich 20, to thereby vaporize the rich flow FS 20 and condense, at least in part, the expanded working fluid FS extraction 10 and FS lean working fluid flow 30, in the RHE 140. As discussed above, the vaporized rich flow FS 20 is fed to either the superheater 144, along with vaporized feed fluid from the boiler 142, or is combined with the superheated working fluid from the superheater 142 and fed directly to the TGSS 130. The condensed expanded working fluid from the RHE 140 forms part of the feed flow, i.e., flow FS 5, to the boiler 142, as has been previously described.
FIG. 2 details a portion of the RHE 140 of VSS 110 of FIG. 1. As shown, the RHE 140 receives ammonia-rich, cold high pressure stream FS rich 20 from DCSS 100. Stream FS rich 20 is heated by ammonia-lean hot low pressure stream FS 3010. The stream FS 3010 is formed by combining the somewhat lean hot low pressure FS extraction stream 10 from TGSS 130 with the lean hot low pressure stream FS 30 from DCSS 100, these flows being combined such that stream FS 30 dilutes stream FS 10 resulting in a desired concentration of ammonia in stream FS 3010.
Heat energy 125, is transferred from stream FS 3010 to stream FS rich 20. As discussed above, this causes the transformation of stream FS 20 into a high pressure vapor stream FS 9 or the high pressure superheated vapor stream FS 9', depending on the pressure and concentration of the rich working fluid stream FS 20. This also causes the working fluid stream FS 3010 to be condensed and therefore serve as a liquid feed flow FS 5 to the boiler 142.
As previously indicated, in one implementation the vapor stream FS 9 along with the vapor output from boiler 142 forms the vapor input to the superheater 144, and the superheater 144 superheats the vapor stream to form superheated vapor stream 40 which is used to power TGSS 130. Alternatively, the superheated vapor steam FS 9' along with the superheated vapor output from the superheater 144 forms the superheated vapor stream FS 40 to the TGSS 130.
FIG. 3 illustrates exemplary heat transfer curves for heat exchanges occurring in the RHE 140 of FIG. 2. A typical Kalina cycle heat exchange is represented by curves 520 and 530. As shown, the temperature of the liquid binary working fluid FS 20 represented by curve 520 increases as a function of the distance of travel of the working fluid through the heat exchanger of the RHE 140 in a substantially linear manner. That is, the temperature of the working fluid continues to increase even during boiling as the working fluid travels through the heat exchanger of the RHE 140 shown in FIG. 2. At the same time, the temperature of the liquid working fluid FS 3010 represented by curve 530 decreases as a function of the distance of travel of this working fluid through the heat exchanger of the RHE 140 in a substantially linear manner. That is, as heat energy 125 is transferred from working fluid FS 3010 to the working fluid stream FS 20 as both fluid streams flow in opposed directions through the RHE 140 heat exchanger of FIG. 2, the binary working fluid FS 3010 loses heat and the binary working fluid stream FS 20 gains heat at substantially the same rate within the Kalina cycle heat exchangers of the RHE 140.
In contrast, a typical Rankine cycle heat exchange is represented by curve 510. As shown, the temperature of the water or water/steam mixture forming the working fluid represented by curve 510 increases as a function of the distance of travel of the working fluid through a heat exchanger of the type shown in FIG. 2 only after the working fluid has been fully evaporated, i.e., vaporized. The portion 511 of curve 510 represents the temperature of the water or water/steam mixture during boiling. As indicated, the temperature of the working fluid remains substantially constant until the boiling duty has been completed. That is, in a typical Rankine cycle, the temperature of the working fluid does not increase during boiling. Rather, as indicated by portion 512 of curve 510, it is only after full vaporization, i.e., full phase transformation, that the temperature of the working fluid in a typical Rankine cycle increases beyond the boiling point temperature of the working fluid, e.g., 212.degree. F.
As will be noted, the temperature differential between the stream represented by curve 530, which transfers the heat energy, and the Rankine cycle stream represented by curve 510, which absorbs the heat energy, continues to increase during phase transformation. The differential becomes greatest just before complete vaporization of the working fluids. In contrast, the temperature differential between the stream represented by curve 530, and the Kalina cycle stream represented by curve 520, which absorbs the heat energy, remains relatively small, and substantially constant, during phase transformation. This further highlights the enhanced efficiency of Kalina cycle heat exchange in comparison to Rankine cycle heat exchange.
As indicated above, the transformation in the RHE 140 of the liquid or mixed liquid/vapor stream FS 20 to vapor or superheated vapor stream FS 9 or 9' is possible in the Kalina cycle because, the boiling point of rich cold high pressure stream FS 20 is substantially lower than that of lean hot low pressure stream FS 3010. This allows additional boiling, and in some implementations superheating, duty to be performed in the Kalina cycle RHE 140 and hence outside the boiler 142 and/or superheater 144. Hence, in the Kalina cycle, a greater portion of the process heat 121 can be used for superheating vaporized working fluid in the superheater 144, and less process heat 121 is required for boiling duty in the boiler 142. The net result is increased efficiency of the power generation system when compared to a conventional Rankine cycle type power generation system.
FIG. 4 further depicts the TGSS 130 of FIG. 1. As illustrated, the TGSS 130 in a Kalina cycle power generation system is driven by a high pressure superheated binary fluid vapor stream FS 40. Relatively lean hot low pressure stream FS extraction 10 is directed from, for instance the exhaust of an HP turbine (not shown) within the TGSS 130 to the RHE 140 as shown in FIGS. 1 and 2. A relatively lean cooler, even lower pressure flow FS extraction 11 is directed from, for instance, the exhaust of an LP turbine (not shown) within the TGSS 130 to the DCSS 100 as shown in FIG. 1. As has been discussed to some extent, both FS extraction flow 10 and FS extraction flow 11 retain enough heat to transfer energy to still cooler higher pressure streams in the DCSS 100 and RHE 140.
A vapor generator of a power generation system is subjected to intense heat energy, a portion of which is converted into vapor which drives turbines producing mechanical motion and ultimately electrical energy. Although there is an advantage to operating at high temperatures, a cooling system is still required that assures the temperature of sensitive components located in high temperature parts of the vapor generator will not exceed a value which may cause damage to those components.
In a vapor generation system, hot combustion gases are heating the tubes of the working fluid delivery subsystems. To protect these tubes from the danger of damage due to overheating, the tubes must be cooled, especially in the high temperature side of the furnace where the tubes are receiving direct radiant energy from the combustion gases.
In another aspect of the cooling system, the combustion gases, in addition to components of the furnace, may also have to be cooled. In particular, in the backpass of the furnace, the combustion gases must be cooled to a smokestack temperature. The combustion gases generated in the combustion chamber travel throughout the furnace by convection loosing heat to the various heating components, and ultimately are expelled into the atmosphere through a smoke stack. Before the gases are expelled into the atmosphere, they must be cooled to below a temperature denoted as the smokestack temperature.